Polymeric treatment and wellbore pump arranged to increase hydrocarbon production

ABSTRACT

Method of increasing the production rate of reservoir fluid from a reservoir including a wellbore pump for pumping wellbore fluid within the wellbore to a surface. The wellbore pump is associated with a production tube and within a casing, whereby an annulus is defined between the casing and the pump and the production tube, and includes reservoir fluid which is contacted with a treatment formulation containing active materials, including a first optionally crosslinked polymeric material having —O— moieties pendent from a polymeric backbone thereof. The wellbore pump is operated to recover liquid hydrocarbons from the wellbore at a rate which is greater after contact with the treatment formulation compared to the rate of recovery of liquid hydrocarbons before contact with the treatment formulation.

This application is a continuation of Application No. 12/452,079 filedMar. 19, 2010 U.S. Pat. 8,672,033, which is a 371 of PCT/GB2008/001868filed Jun. 3, 2008, which claims priority to British Patent ApplicationNo. 0711635.3 filed Jun. 15, 2007.

This invention relates to hydrocarbons and particularly, although notexclusively, relates to the production of hydrocarbons. Preferredembodiments aim to improve performance of pumps associated with awellbore and/or increase the rate of production of hydrocarbons.

BACKGROUND OF THE INVENTION

During the process of hydrocarbon production under the naturalgeothermal pressure of a reservoir, the reservoir pressure will deplete.Eventually, the pressure in the reservoir may become too low to forcefluid from the producing zone to the surface and artificial-lift may berequired. In some cases, artificial-lift techniques are employed at thevery onset of production, depending upon the overall techno-economiccharacteristics of the reservoir.

An artificial-lift system is defined as any system which adds energy tothe fluid column in a wellbore, with the objective of initiating andimproving production from the well. Artificial-lift methods fall intotwo groups, those that use gas and those that use pumps.

In a gas lift method, gas is injected into a well through valves placedalong the wellbore at strategic points. The gas aerates fluid to make itless dense and consequently the reservoir pressure becomes sufficient tolift the oil and force it from the wellbore.

Methods that use pumps use a surface power source to drive a downholepump assembly. The objective is to generate a large positive pressuregradient between the exit point of the pump and the surface, in order toincrease the rate of fluid transport to the surface. In addition,downhole pumps serve to reduce pressure between the pump entry point andthe wellbore interface with the reservoir. This increases thedifferential pressure between the reservoir and the wellbore, which inturn may increase the rate of fluid flow into the wellbore, providingthe reservoir is compliant.

In its passage from a reservoir to the surface, fluid includinghydrocarbons is arranged to flow through various orifices, openings orother constrictions. For example, when a pump is arranged in thewellbore, the fluid must pass through the inlet opening of the pumpbefore it is lifted to the surface. Also, in some cases, wellbores mayinclude associated sand control barriers (also known as “sand packs”,“sand screens” or “gravel packs”), upstream of a wellbore pump. The sandcontrol barriers are provided for maintaining structural integrity ofthe wellbore in the absence of casing whilst still allowing fluid topass from the reservoir into the wellbore and also control the migrationof formation sand into the wellbore pumps and/or surface equipment.However, sand control barriers can act as a significant force workingagainst the passage of fluid into the wellbore.

Disadvantageously, the passage of fluid including hydrocarbons throughconstrictions as described may produce a significant positive pressurewhich may reduce the rate of flow of fluid from the reservoir to thewellbore and/or into the wellbore pump.

SUMMARY OF THE INVENTION

It is an object of the present invention to address the above describedproblems.

According to a first aspect of the invention, there is provided a methodof improving performance or efficiency of a wellbore pump associatedwith a wellbore and/or for increasing the rate of production ofreservoir fluid from a reservoir, wherein a wellbore pump is arranged topump wellbore fluid within the wellbore to a surface, said methodcomprising the steps of:

(a) selecting a wellbore which includes an associated wellbore pump; and

(b) contacting a reservoir fluid upstream of an inlet of the wellborepump with a treatment formulation, wherein said treatment formulationcomprises a first polymeric material which includes —O— moieties pendentfrom a polymeric backbone thereof, wherein the first polymeric materialis optionally cross-linked.

Surprisingly, it has been found that use of the treatment formulationappears to facilitate passage of reservoir fluid including liquidhydrocarbons through constrictions by lowering the surface tensionand/or frictional forces between the reservoir fluid and walls whichdefine constrictions. The walls may be of the near wellbore pores,residing in the reservoir; or may be walls of production tubing from thepump outlet to the surface; or may be walls of orifices of the pumpinlet or outlet; or may be internal walls within pumps themselves; ormay be within sand control barriers. Such reduced forces may facilitatepassage of reservoir fluid and consequently may improve performance orefficiency of a pump associated with a wellbore. Furthermore, use of thetreatment formulation may advantageously allow the rate of flow of fluidpassing from the reservoir into the wellbore to increase andconsequently the barrels of oil per day (BOPD) may be increased which iseconomically and commercially very significant.

In one embodiment, use of the treatment formulation may simply reducethe torque on the wellbore pump. However, in a second embodiment, theheight of the head of reservoir fluid in a wellbore annulus may belowered and, consequently, the back pressure due to the head will bereduced and the reservoir may then yield more oil. In a third embodimentin which a wellbore includes an associated sand control barrier, use ofthe treatment formulation may facilitate flow of oil through thebarrier, reduce back pressure and the reservoir may therefore yield moreoil. In a fourth embodiment, the method may be used to increase the rateof production of a non-producing or “dry” well.

Said reservoir fluid suitably comprises liquid hydrocarbons, for exampleoil such as heavy oil. The method may advantageously be used to increasethe rate of production of the aforementioned liquid hydrocarbons.

In step (b), said reservoir fluid is preferably initially contacted withsaid treatment formulation in said wellbore.

In one embodiment, said wellbore may have a maximum deviation in therange 0 to 60°. The maximum deviation may be in the range 0 to 30° C.Said wellbore may extend substantially vertically. In anotherembodiment, the invention may be used for increasing the rate ofproduction of reservoir fluids from horizontal wells or wells by havingwellbores which deviate more than 60°.

Prior to contact with said reservoir fluid, said treatment formulationis suitably above the surface of the ground in which said wellbore isdefined. It may be contained within a receptacle. In step (b), saidtreatment formulation is preferably caused to move from a firstposition, spaced from the inlet of the wellbore pump, towards a secondposition defined by the inlet of the wellbore pump. Said treatmentformulation is preferably arranged to move along a fluid flow path whichextends within the wellbore (preferably within an annulus of thewellbore) on moving towards said second position. Preferably, said fluidflow path extends between a first region of the wellbore adjacent anupper end of the wellbore and a second region of the wellbore which issuitably below the first region, preferably at or adjacent said inlet ofsaid pump. Preferably, substantially the entirety of said fluid flowpath extends within the wellbore. Said fluid flow path may extend atleast 10 m, preferably at least 30 m.

Preferably, in step b), a force is incident upon the treatment fluid tocause it to move between said first and second positions. Said forcecould be provided, at least in part, by a pump means. Preferably, amajor amount of said force is provided by gravity. Suitably, at least60%, preferably at least 70%, more preferably at least 80%, especiallyat least 90% of said force is provided by gravity. In a preferredembodiment, treatment formulation is introduced into said wellbore andallowed to fall under gravity thereby to move towards the wellbore pump.In this case, suitably, no pump means may be used to speed up flow ofthe treatment formulation within the wellbore.

In a first preferred embodiment, in step (b), said treatment formulationmay be initially contacted with reservoir fluid in the annulus of thewellbore. The treatment formulation may, after initial contact, beallowed to fall under gravity and move towards the inlet of the wellborepump. When the annulus does not include a packer (or other, interruptiontherein), the treatment formulation may be introduced at or adjacent thetop of the annulus. When the annulus includes a packer (or otherinterruption), the treatment formulation may be introduced beyond thepacker so that it is free to move (suitably under gravity) towards theinlet of the wellbore pump. In this regard, a conduit may be definedthrough the packer (or other interruption) to allow treatmentformulation to traverse the packer.

Preferably, treatment formulation is initially contacted with reservoirfluid at a position which is at least 5 m above the height of the inletof the wellbore pump. If the wellbore includes more than one pump, thereferenced pump is suitably the lowermost one.

In a second less preferred embodiment, a conduit for containingtreatment formulation may extend to a position adjacent the inlet of thepump for delivering formulation directly to a region around the inlet.The conduit may be terminated with a delivery device having a plurality,preferably a multiplicity, of outlets for directing streams of treatmentformulation to the region around the inlet.

Said treatment formulation may be introduced into the wellbore from aninput position, wherein the input position is on an imaginary verticalline which is spaced horizontally from the inlet of the wellbore pump bya distance of less than 500 m, preferably less than 50 m, morepreferably less than 10 m. Thus, in the first embodiment described, thefirst position may be the position wherein treatment formulationinitially contacts reservoir fluid (and the imaginary vertical line mayextend vertically downwards from that position). In the secondembodiment, the first position may be defined by an outlet of thedelivery device.

A filtration device, for example a sand control barrier, may beassociated with the wellbore, upstream of the wellbore pump. The methodmay particularly advantageously be applied to such arrangements,potentially leading to an increase in BOPD of a well.

Said wellbore pump may be of any type. Preferably, said wellbore pump isselected from a progressing cavity pump (PCP) (also known as aneccentric screw pump), a beam pump (also known as a rod pump, walkingbeam pump and a suction rod pump) and a centrifugal pump for example anelectrical submersible pump (ESP).

A PCP is a type of pump which transfers fluid via a sequence of smalldiscrete cavities, which move through the pump. These cavities carry thefluid. The PCP is comprised of a helix shaped metal rotor, which turnseccentrically inside a helix shaped stator. The exact shape and pitch ofthe helices on both rotor and stator, the number of cavities per lengthof pump and the size of the gaps between rotor and stator are alloptimized for well conditions and pump size.

Beam pumps are simple devices containing a plunger and a pair of valveson the end of a reciprocating beam (sucker rod), which travelslongitudinally in the production tubing of a well. Such a device isdriven by a surface power source, commonly an electric motor or a gas ordiesel engine. This turns a pair of cranks which by their actionconverts the rotary mechanism of the motor to the vertical reciprocatingmotion of the beam. The result is a characteristic nodding motion. Thedownhole plunger and valve assembly convert the reciprocating motion tovertical fluid movement. Essentially, during the downstroke of the beamthe plunger is filled with fluid and during the upstroke of the beam thefluid is delivered to the front surface of the pump.

The method may be used particularly advantageously with theaforementioned wellbore pumps because it may allow performance and/orefficiency of the pumps to be increased and/or may reduce wear and/orservice intervals of the pumps.

Preferred pumps may, in some cases, be PCPs or beam pumps. However, insome cases, the invention may advantageously be applied to situationswherein EPSs are associated with wellbores. ESPs are generallyrelatively cheap but are not generally usable to transport heavy oils.However, use of the present invention may enable such pumps to be used,even to transport relatively heavy oils to the surface.

In step (a), the method may comprise selecting a wellbore having awellbore pump of the type described.

In step (a), the method may comprise selecting a wellbore having ahydrostatic head in the annulus which is at least 15 m, preferably atleast 30 m above the level of the inlet of said wellbore pump. The headmay be less than 300 m above said level.

In step (a), the method may comprise selecting a wellbore associatedwith a reservoir which is capable of yielding more oil if the rate offlow through the wellbore can be increased. The method may have theeffect of stimulating the reservoir so that it yields more oil.

In step (a), the method may comprise selecting a wellbore having awellbore pump having a volumetric efficiency of less than 60%.

In step (a), the method may comprise selecting a wellbore wherein oil inthe wellbore fluid has a viscosity in the range 2000 cp to 50,000 cp,preferably 5000 cp to 50,000 cp, measured at the reservoir temperature.

In the method, the treatment formulation may be introduced into a regionupstream of the wellbore pump (e.g. introduced into the wellbore and/orthe annulus thereof) at a rate of at least 0.1 litres of treatmentformulation per minute. The rate may be 500 litres per minute or less.In preferred embodiments, the rate may be at least 0.25 litres/minute;and suitably 25 litres/minute or less.

In the method, the ratio of the volume of reservoir fluid to the volumeof treatment formulation may be in the range of 60:40 (reservoirfluid:formulation) to 95:5, preferably in the range of 70:30 (reservoirfluid:formulation) to 85:15.

The method of the first aspect suitably includes the step of operatingthe wellbore pump to draw fluid through the wellbore, suitably to thesurface.

Preferably, in the method, the rate of recovery of liquid hydrocarbonsfrom the wellbore after contact with said treatment formulation isgreater than the rate of recovery of liquid hydrocarbons before contactwith said treatment formulation.

Preferably, the method comprises causing or allowing liquid hydrocarbonto separate from other components (e.g. water) of the fluid collected atthe surface of the wellbore.

Said treatment formulation suitably has a substantially Newtonianviscosity at 25° C. of greater than 0.75 cP, suitably greater than 0.9cP. Said treatment formulation preferably has a viscosity under theconditions described of not greater than 10 cP, preferably of 5 cP orless, more preferably of 2 cP or less. However, in the embodiment of thefourth aspect described herein, the viscosity may be higher.

Said treatment formulation may include at least 70 wt %, preferably atleast 80 wt % water. The amount of water may be 99.9 wt % or less.

Said treatment formulation suitably includes at least 0.1 wt % of saidoptionally cross-linked first polymeric material. Said formulationsuitably includes less than 5 wt %, preferably less than 3 wt %, morepreferably less than 2 wt %, especially less than 1 wt % of saidoptionally cross-linked first polymeric material.

Said treatment formulation may include at least 30 parts by weight (pbw)of water to each pbw of said optionally cross-linked polymeric material.

In a preferred embodiment, said treatment formulation includes:

-   -   0.1 to 3 wt % (preferably 0.1 to 0.5 wt %) of said optionally        cross-linked polymeric material;    -   0 to 20 wt % of dissolved or dispersed components in addition to        said optionally cross-linked polymeric material (e.g. salts        found in sea water);    -   77 to 99.9 wt % water.

In an especially preferred embodiment, said treatment formulationincludes:

-   -   0.1 to 0.5 wt % of said optionally cross-linked polymeric        material;    -   0 to 10 wt % of said dissolved or dispersed components;    -   89.5 to 99.9 wt % water.

Water for use in the treatment formulation may be derived from anyconvenient source. It may be potable water, surface water, sea water,aquifer water, deionised production water and filtered water derivedfrom any of the aforementioned sources.

Suitably, said optionally cross-linked first polymeric material makes upat least 90 wt %, preferably at least 95 wt %, more preferably at least98 wt %, especially at least 99 wt % of active materials in saidtreatment formulation. In the most preferred embodiment, preferablysubstantially the only active material in said treatment fluidformulation is said optionally cross-linked first polymeric material.

Said optionally cross-linked first polymeric material is preferablysoluble in water at 25° C. Preferably, said treatment formulationcomprises a solution of said optionally cross-linked first polymericmaterial.

Said polymeric backbone of said first polymeric material preferablyincludes carbon atoms. Said carbon atoms are preferably part of —CH₂—moieties. Preferably, a repeat unit of said polymeric backbone includescarbon to carbon bonds, preferably C—C single bonds. Preferably, saidfirst polymeric material includes a repeat unit which includes a —CH₂—moiety. Preferably, said polymeric backbone does not include any —O—moieties, for example —C—O— moieties such as are found in an alkyleneoxypolymer, such as polyethyleneglycol. Said polymeric backbone ispreferably not defined by an aromatic moiety such as a phenyl moietysuch as is found in polyethersulphones. Said polymeric backbonepreferably does not include any —S— moieties. Said polymeric backbonepreferably does not include any nitrogen atoms. Said polymeric backbonepreferably consists essentially of carbon atoms, preferably in the formof C—C single bonds.

Said —O— moieties are preferably directly bonded to the polymericbackbone.

Said optionally cross-linked first polymeric material preferablyincludes, on average, at least 10, more preferably at least 50, —O—moieties pendent from the polymeric backbone thereof. Said —O— moietiesare preferably a part of a repeat unit of said first polymeric material.

Preferably, said —O— moieties are directly bonded to a carbon atom insaid polymeric backbone of said first polymeric material, suitably sothat said first polymeric material includes a moiety (which ispreferably part of a repeat unit) of formula:

where G¹ and G² are other parts of the polymeric backbone and G³ isanother moiety pendent from the polymeric backbone. Preferably, G³represents a hydrogen atom. Preferably, said first polymeric materialincludes a moiety

Said moiety III is preferably part of a repeat unit. Said moiety III maybe part of a copolymer which includes a repeat unit which includes amoiety of a different type compared to moiety III. Suitably, at least 60mole %, preferably at least 80 mole %, more preferably at least 90 mole% of said first polymeric material comprises repeat units which comprise(preferably consist of) moieties III. Preferably, said first polymericmaterial consists essentially of repeat units which comprise (preferablyconsist of) moieties III.

Suitably, 60 mole %, preferably 80 mole %, more preferably mole %,especially substantially all of said first polymeric material comprisesvinyl moieties.

Preferably, the free bond to the oxygen atom in the —O— moiety pendentfrom the polymeric backbone of said first polymeric material (andpreferably also in moieties II and III) is bonded to a group R¹⁰ (sothat the moiety pendent from the polymeric backbone of said firstpolymeric material is of formula —O—R¹⁰. Preferably group R¹⁰ comprisesfewer than 10, more preferably fewer than 5, especially 3 or fewercarbon atoms. It preferably only includes atoms selected from carbon,hydrogen and oxygen atoms. R¹⁰ is preferably selected from a hydrogenatom and an alkylcarbonyl, especially a methylcarbonyl group. Preferablymoiety —O—R¹⁰ in said polymeric material AA is an hydroxyl or acetategroup.

Said first polymeric material may include a plurality, preferably amultiplicity, of functional groups (which incorporate the —O— moietiesdescribed) suitably selected from hydroxyl and acetate groups. Saidpolymeric material preferably includes at least some groups wherein R¹⁰represents an hydroxyl group. Suitably, at least 30%, preferably atleast 50%, especially at least 80% of groups R¹⁰ are hydroxyl groups.Said first polymeric material preferably includes a multiplicity ofhydroxyl groups pendent from said polymeric backbone; and also includesa multiplicity of acetate groups pendent from the polymeric backbone.

The ratio of the number of acetate groups to the number of hydroxylgroups in said first polymeric material is suitably in the range 0 to 3,is preferably in the range 0.1 to 2, is more preferably in the range 0.1to 1.

Preferably, substantially each free bond to the oxygen atoms in —O—moieties pendent from the polymeric backbone in said first polymericmaterial, except for any free bonds which are involved in optionallycross-linking the first polymeric material, is of formula —O—R¹⁰ whereineach group —OR¹⁰ is selected from hydroxyl and acetate.

Preferably, said first polymeric material includes a vinyl alcoholmoiety, especially a vinyl alcohol moiety which repeats along thebackbone of the polymeric material. Said first polymeric materialpreferably includes a vinyl acetate moiety, especially a vinylacetatemoiety which repeats along the backbone of the polymeric material.

Polyvinylalcohol is generally made by hydrolysis of polyvinylacetate.Said first polymeric material may comprise a 0-100% hydrolysed, suitablya 5 to 95% hydrolysed, preferably a 60 to 95%, more preferably a 70 to95%, especially a 80 to 90%, hydrolysed polyvinylacetate

Said first polymeric material may have a number average molecular weight(Mn) of at least 10,000, preferably at least 50,000, especially at least75,000. Mn may be less than 500,000, preferably less than 400,000. Saidfirst polymeric material is preferably a polyvinyl polymer. Said firstpolymeric material may be a copolymer.

Said first polymeric material preferably a polyvinyl alcohol polymer orcopolymer.

Preferably, said first polymeric material includes at least one vinylalcohol/vinyl acetate copolymer which may include greater than 5%,suitably includes greater than 30%, preferably greater than 65%, morepreferably greater than 80% of vinyl alcohol moieties.

Said first polymeric material may be a random or block copolymer.

Preferably, said first polymeric material is not cross-linked.

When however said first polymeric material is cross-linked, it maycomprise a polymeric material formed by reaction of a said firstpolymeric material and a second material which includes a functionalgroup which is able to react in the presence of said first polymericmaterial to cross-link said first polymeric material and form a thirdpolymeric material.

Preferably, formation of said third polymeric material from said firstpolymeric material and second material involves a condensation reaction.Preferably, formation of said third polymeric material involves an acidcatalysed reaction.

Preferably, said first polymeric material and second material includefunctional groups which are arranged to react, for example to undergo acondensation reaction, thereby to form said third polymeric material.Preferably, said first polymeric material and second material includefunctional groups which are arranged to react for example to undergo anacid catalysted reaction thereby to form said third polymeric material.

Said second material may be an aldehyde, carboxylic acid, urea,acroleine, isocyanate, vinyl sulphate or vinyl chloride of a diacid orinclude any functional group capable of condensing with one or moregroups on said first polymeric material. Examples of the aforementionedinclude formaldehyde, acetaldehyde, glyoxal and glutaraldehyde, as wellas maleic acid, oxalic acid, dimethylurea, polyacroleines,diisocyanates, divinyl sulphate and the chlorides of diacids.

Said second material is preferably an aldehyde containing or generatingcompound. Preferably, said second material is an aldehyde containingcompound and more preferably includes a plurality of aldehyde moieties.Said aldehyde containing compound may be of formula IV as described inWO98/12239 the content of which is incorporated herein forWO2006/106300.

According to a second aspect of the invention, there is provided asystem associated with a wellbore, the system comprising:

a receptacle for containing a treatment formulation; conduit meansextending from the receptacle and being arranged to deliver treatmentformulation from the receptacle to a position wherein it contactsreservoir fluid.

The wellbore suitably includes a wellbore pump.

Preferably, the conduit means is arranged to introduce treatmentformulation into the wellbore from an input position, wherein the inputposition is on an imaginary vertical line which is horizontally spacedfrom the inlet of the wellbore pump by a distance of less than 500 m,preferably less than 25 m, more preferably less than 10 m.

Preferably, the receptacle contains a treatment formulation whichcomprises a first polymeric material which is optionally cross-linked asdescribed according to the first aspect.

The system may include means for collecting fluid extracted from thewellbore by the wellbore pump and for allowing separation of liquidhydrocarbons from said treatment formulation.

The system of the second aspect may have any feature described withreference to the method of the first aspect. The system may be forcarrying out the method of the first aspect.

In a third aspect, there is provided the use of an optionallycross-linked first polymeric material as described according to thefirst aspect for treating a wellbore for improving the performance orefficiency of a wellbore pump and/or for increasing the rate ofproduction of reservoir fluid from a reservoir which communicates withthe wellbore.

Any feature of any aspect of any invention or embodiment describedherein may be combined with any feature of any aspect of any otherinvention or embodiment described herein mutatis mutandis.

BRIEF DESCRIPTION OF THE DRAWINGS

Specific embodiments of the invention will now be described, by way ofexample, with reference to the following drawings, in which:

FIG. 1 is a schematic representation of an oil well;

FIG. 2 is a view similar to that of FIG. 1 except the well includes asand pack;

FIG. 3 is a graph illustrating results for Example 3; and

FIG. 4 is a schematic representation of an oil well including analternative means of delivering an aqueous formulation thereinto.

DETAILED DESCRIPTION OF THE INVENTION

In the figures, the same or similar parts are annotated with the samereference numerals.

Referring to FIG. 1, an oil well includes a wellbore 2, below groundlevel 4, which extends to an oil reservoir 6. The wellbore includes acasing 8 within which is arranged a progressing cavity pump (PCP) 10which includes an inlet 12 at its lower end and is connected at itsupper end to production tube 14. An annulus 16 is defined between thepump 10/tube 14 and the casing 8. The annulus communicates with thereservoir and includes a head 20 of reservoir fluid. A water basedformulation as hereinafter described can be poured down the annulus 16and pass under gravity to the reservoir 6, immediately upstream of inlet12. The formulation may improve the performance and efficiency of thepump 10 due to its ability to increase the mobility of the oil in thereservoir immediately upstream of the pump 10 and/or enhance the abilityof the oil to enter the pump inlet. Furthermore, by improving mobilityand/or reducing the level of back pressure when the oil enters the pumpinlet (or any other constriction) the rate of flow of oil from thereservoir into the wellbore may be increased resulting in an increasedrate of oil production.

The water-based formulation comprises a 0.5 wt % aqueous solution of a88% hydrolysed polyvinylalcohol having a molecular weight of 180,000.This may be commercially available or may be made by known methods whichmay involve diluting more concentrated polyvinylalcohol solutions.

In a variation on the FIG. 1 embodiment, a wellbore may include anassociated sand pack 40 as shown in FIG. 2. The sand pack effectivelyfilters sand particles from oil as oil passes from the reservoir intothe wellbore to prevent such sand particles passing into pump 10 andpassing to the surface. However, the sand pack acts as a constriction tothe passage of oil into the wellbore, since the oil must pass throughthe openings of the sand pack to enter the wellbore.

The arrangement of FIG. 2 may be treated with the water-basedformulation as described for Example 1. In this case, it is found thatthe performance and/or efficiency of pump 10 may be improved, and therate of oil production may also be increased.

The use of the treatment formulation is believed to facilitate passageof reservoir fluid including oil through orifices (or otherconstrictions) for example through pump inlets and sand packs byreducing surface tension of the oil and/or interfacial tension betweenthe oil and walls which define constrictions. By reducing the effectivefriction between the oil and walls which define constrictions, the oilmay more easily pass through the constrictions into the wellbore and/orpump. As a result, the rate of flow of oil from the reservoir into thewellbore may be increased and/or the efficiency of wellbore pumps may beimproved, possibly allowing pump speeds to be increased.

Whilst the applicant does not wish to be bound by any theory, it isbelieved that the effect the aqueous formulation has to improve “slip”of the oil relative to solid bodies (such as walls which defineconstrictions) may be illustrated by the simple experiment described inExample 1.

EXAMPLE 1

A 500 ml stoppered jar containing 125 ml of an aqueous formulationcomprising 0.5 wt % of polyvinylalcohol as described above was selectedand the formulation manually swirled around so that it wetted the wallsof the jar. Then 250 ml of crude oil was poured on top of the aqueousformulation with minimum agitation. The jar was then manually lifted androcked from side to side and the fluid therein caused to gently swirlaround the jar. It was observed that the oil was very mobile and did notstick to the jar wall.

The process described was repeated except that tap water alone was usedinstead of the polyvinylalcohol-containing aqueous formulation. In thiscase, the oil was observed to be far less mobile and furthermoreglobules and/or patches of oil stuck to the jar wall. Thus, it is clearthat use of the aqueous formulation significantly increases oilmobility.

Not all wells can be treated as aforesaid to improve performance andefficiency of pumps and, accordingly, appropriate wells need to beselected for treatment. Factors which may affect whether a well canadvantageously be treated using the method described are discussedbelow.

-   (a) A very high head 20 in the annulus may indicate that the pump 10    is working at less than the optimum.-   (b) In the absence of taking steps to stimulate the reservoir, for    successful application of the method the reservoir should preferably    be capable of yielding more oil if pumps can be run at greater    efficiencies and/or higher pump speeds. This is not always the case.    Some pumps are well matched to reservoirs, which are delivering at    their maximum rate. In these cases no improvement in pump    performance will yield more oil. Indeed, increasing pump    rates/performance may result in the preferential extraction of water    from the reservoir rather than oil. However, in some cases, the    reservoir itself may be stimulated by the treatment described to    produce more oil. For example, when a wellbore includes an    associated sandpack (or oil is otherwise constricted from entering a    pump inlet), use of the aqueous formulation may reduce a back    pressure on the reservoir caused by the presence of the sandpack (or    other constriction) and, as a result, use of the aqueous formulation    may stimulate the reservoir to yield more oil.-   (c) Provided a reservoir can produce more oil with an increase in    pump efficiency and/or pump revolutions/strokes per minute (rpm),    and/or via stimulation, then the maximum increase in total    production is given by:    Maximum increase=IP×pump intake pressure    wherein IP is the production index, defined as

$\frac{Q}{\left( {{{reservoir}\mspace{14mu}{pressure}} - {{pump}\mspace{14mu}{intake}\mspace{14mu}{pressure}}} \right)}$where Q is the rate of fluid production from the reservoir in barrelsper day and all pressures are in pounds per square inch (psi).

The pump intake pressure can be calculated fromPump intake pressure=rho×g×h,where h is the height of the hydrostatic head of fluid above the pumpintake (FIG. 1), g is the acceleration due to gravity and rho is thedensity of the fluid above the pump. The units for rho, g and h areselected to yield a pump intake pressure in psi.

The above equation is for a fluid at a pump intake pressure above thebubble point. If the pump intake pressure is lower than the bubblepoint, gas may be released from the oil, which may damage theperformance of the pump or at best invalidate the equation defining IP.

-   (d) The pump may have a bottleneck at its suction point, related to    the low mobility of the oil, i.e. the low mobility is preventing the    pump from working at higher efficiencies and at higher rotation    speeds. If limitations are due to worn out pumps, or oil mobility    does not provide the limitation, using the method described may not    help.-   (e) The maximum increase in oil mobility may be seen for a high    viscosity oil in a cold reservoir.-   (f) It is desirable to have low BS&W (basic sediment and water) in    order that the extra fluid produced is rich in oil, and therefore    more valuable.-   (g) The water-based formulation is suitably capable of increasing    the mobility of the oil at the entry to the pump and/or through    other constrictions.-   (h) The water-based formulation may increase mobility above the pump    in order to minimize back pressure on the pump.-   (i) The pump is preferably in good condition as determined by    manometric tests. Worn out pumps may slip badly with the water-based    formulation and deliver less oil than anticipated.-   (j) The installed pump is suitably running at low volumetric    efficiency and have the potential to be increased. Preferably,    volumetric efficiency (prior to application of the method),    calculated from field production rates at known pump speeds, should    be below 60%. This parameter is not a true energy efficiency, but is    taken as an indicator of the ability of the water-based formulation    to increase the performance of the reservoir and pump assembly. It    should be interpreted in combination with the pump intake pressure    (point (c)).-   (k) When exposed to increased drawdown by the pump, the producing    zone must not produce significant additional water.

It should be noted that the object of practising the method described isnot solely to lower the height of head 20 as much as possible sincethere does need to be some head in order to prevent ingress of air orgas into the pump intake, which could damage the pump. In addition, forsome pumps, the delivery of the water based formulation to the annuluswill result in an increase in the level of fluid, above the pump, whichis in hydraulic contact with the reservoir. This fluid above the pumphas the effect of applying a hydrostatic pressure on the reservoir atthe point of hydrocarbon production, the effect of which is to actagainst the tendency of the reservoir to produce fluid, i.e. to limitthe rate of oil production. This means that the rate of delivery of thewater-based formulation should be optimised to minimise factors thatwork against the increase of oil production.

Furthermore, the object of practising the method described is not solelyto increase oil mobility the maximum amount possible. This is becausefor some pumps (e.g. PCP's), if the frictional force between the fluidentering the pump and the pump itself is too low, the fluid may slipinside the pump as the rotor is turned which leads to reduced pumpefficiency. This effect can be compounded with pumps designed toaccommodate sand production accompanying oil production (as in CHOPS).In such cases, the gaps between rotor and stator are necessarily large,leading to an increased slip of low friction fluids. Careful control offluid compositions and delivery rates may therefore be important.

In applications of the method described, a water based formulation willbe delivered to a pump inlet and it will be necessary for the pump tocarry this added fluid to the surface. The resulting improvement in pumpperformance must be such as to allow the pump speed to be increased by aproportion which is sufficient to accommodate the additional fluiddelivered and still transport produced oil.

The ratio of formulation to oil will have to be optimized on awell-by-well basis, in order to achieve maximum oil production.Suitably, the formulation will be delivered at between 60:40Oil:Formulation through to 95:5 Oil:Formulation, preferably in the range70:30 to 85:15.

Details of field trials to illustrate use of the method are described inExamples 2 and 3 below.

EXAMPLE 2

A candidate well was selected, based on an assessment of the factorsdescribed in (a) to (k) above, as having high potential for an increasein oil production rate by treatment with the water-based formulationdescribed. The well had a sand control barrier. The initial oilproduction rate of the well was approximately 48 BPD.

A 0.5 wt % polyvinylalcohol aqueous solution was introduced into theannulus by simply pouring it down the annulus. The delivery rate wasoptimised over a four day period by trial and error. The table belowshows data for two situations. One is the case where no aqueous solutionwas introduced (i.e. a baseline). The second case is for when theaqueous solution was introduced at an optimised rate of 23 BPD.

Pump Aqueous Oil Speed solution Torque WHP Rate Pump Title RPM rate BPDLb. ft psi BPD Efficiency % Baseline 206 0 248 50 48.3 43 Trial 275 23211 16 76 59.5

In summary, it was found that delivery at the optimum rate resulted inthe following:

-   -   i. the ability to increase the pump speed by 34% from 206 RPM to        275 RPM.    -   ii. a greater than 55% increase in oil production from 48 BPD to        76 BPB. This increase of 28 BPD is greater than would be        predicted by using the aforementioned equation (maximum        increase=IP×pump intake pressure). This implies the IP has been        increased by the treatment which indicates the productivity fo        the near wellbore reservoir has been improved.    -   iii. an increase in the volumetric efficiency of the pump from        43% to almost 60%    -   iv. a 15% reduction in pump torque from 248 lb·ft to 211 lb·ft    -   v. a 68% reduction in wellhead pressure (WHP) from 75 psi to 16        psi

After completion of the trial, the pump rate was returned to a low rate(206 RPM) and the hydrocarbon production rate was observed to return toits initial low value of approximately 50 BPD.

EXAMPLE 3

A candidate well was selected, based on an assessment of the factorsdescribed in (a) to (k) above, as having high potential for reduction indownhole pump torque and wellhead pressure by treatment with thewater-based formulation described. In this case, the well had no sandpack. The initial oil production rate of the well was approximately 109BPD.

A 0.7 wt % polyvinylalcohol aqueous solution was introduced into theannulus at a delivery rate of 26 BPD. After a period of 8 hoursdelivering the formulation at 26 BPD, with the downhole pump set at 90RPM, the downhole pump speed was increased to 110 RPM for the durationof the trial.

FIG. 3 shows the changes in pump torque (Lb·ft) and wellhead pressure(psi) as a function of time as the formulation was being delivered. Themeasured values of pump torque are divided by 2 in order to scale thedata so both torque and wellhead pressure can be shown on one figure.Time zero is the time at which the delivery of the formulation began.

FIG. 3 shows that there is an initial period of up to 15 hours, duringwhich both pump torque and wellhead pressure vary erratically, finallystabilising to levels that are 25% and 70% less than their startingvalues. However, during the trial, the pump delivering aqueousformulation was turned off after about 20 hours for a 3 hour period. Asa result the pump torque and the wellhead pressure rose at about 30hours but returned to a lower level later. This clearly illustrates how,in the absence of the water-based formulation, pump torque is higher.

The water-based formulations may be advantageously used with PCPs asdescribed above. In addition, it is noted that such water-basedformulations generally will not attack PCP stators which are lined withrubber or elastomers, in contrast to organic solvents which could attachstators. Thus, it is believed that the water-based formulation will notcontribute to wear or degradation of the stators or materials from whichthey are made.

The water-based formulations may also be used to improve performance orefficiency of beam pumps. Factors affecting performance/efficiency andthe application of the water based formulation may be generally asdescribed for PCPs as described above.

As described above, the water-based formulation may simply be poureddown the annulus and because the formulation generally has a densitywhich is greater than that of the oil in the annulus it will fall undergravity and travel to the bottom of the annulus to a position adjacentthe inlet of the pump. The presence of the formulation in this regionenhances the ability of the oil to enter the inlet of the pump. It willbe appreciated that intimate mixing of oil and formulation is unlikelyto take place adjacent the inlet because in the embodiment described nomeans is provided for encouraging mixing.

In some wells, the annulus may be interrupted, for example by a packeror other device introduced to isolate geological zones of the welland/or to stabilise regions of the well, and consequently it will not bepossible to simply pour formulation down the annulus. In this case, atube may be inserted down the annulus and through any packer or otherdevice which otherwise blocks the annulus, the tube being arranged todeliver formulation to the reservoir at a position adjacent the inlet ofthe pump.

In another embodiment a more complex fluid delivery apparatus may beprovided for delivering formulation to the reservoir. Referring to FIG.4, a delivery apparatus 50 is shown extending down the annulus 16 fromabove ground level 4 to the inlet 12 of the pump 10. The apparatus 50includes an elongate tube 52 extending from above ground level, throughany packer or other obstruction (none being shown) to a toroidal tube 54which surrounds the inlet 12 of the pump. The toroidal tube includes anarray of openings (not shown) via which fluid may exit the apparatus.The openings are arranged so that fluid exiting the tube can berelatively evenly delivered around the inlet.

The apparatus may be arranged to provide an additional force to activelydraw hydrocarbon from the reservoir. This may be achieved by flowing theformulation through nozzles or jets connected to the toroidal tube,which can accelerate the rate of hydrocarbon flow via the venturieffect.

Furthermore, the formulation may suitably be delivered at above thehydrostatic pressure experienced at the pump inlet which is preferablyabove the bubble point of the oil.

In each of the embodiments described above, the delivery rate offormulation through the apparatus may be controlled according to the oilproduction rate and the ratio of oil to formulation. For oil wellsproducing between 10 BPD and 500 BPD, the expected delivery rates forthe formulation will be 0.25 litres/minute to 10 litres/minute. Internaldiameters of delivery tubing would be in the range 0.1 inches to 0.8inches, preferably 0.2 inches to 0.5 inches.

The invention is not restricted to the details of the foregoingembodiment(s). The invention extends to any novel one, or any novelcombination, of the features disclosed in this specification (includingany accompanying claims, abstract and drawings), or to any novel one, orany novel combination, of the steps of any method or process sodisclosed.

The invention claimed is:
 1. A method of increasing a rate of productionof reservoir fluid from a reservoir which includes a wellbore pump,wherein said wellbore pump is arranged to pump wellbore fluid within thewellbore to a surface, said method comprising the steps of: (a)selecting a wellbore which includes an associated wellbore pump, saidwellbore pump being associated with a production tube and being arrangedwithin a casing, wherein an annulus is defined between the casing andthe pump and between the casing and the production tube, said annulusincluding reservoir fluid which has a hydrostatic head which is at least15 m above the level of an inlet of the wellbore pump; (b) contacting areservoir fluid in said annulus upstream of an inlet of the wellborepump with a treatment formulation, wherein said treatment formulationcomprises active materials, said active materials comprising a firstpolymeric material which includes —O— moieties pendent from a polymericbackbone thereof, wherein the first polymeric material is optionallycross-linked; and (c) operating said wellbore pump to recover liquidhydrocarbons from the wellbore at a rate which is greater after contactwith said treatment formulation compared to the rate of recovery ofliquid hydrocarbons before contact with said treatment formulation. 2.The method according to claim 1, the method comprising lowering theheight of said hydrostatic head of reservoir fluid in said wellboreannulus.
 3. The method according to claim 1, wherein said hydrostatichead is at least 30 m above the level of the inlet of the wellbore pump.4. The method according to claim 1, wherein, in step (b), said treatmentformulation is caused to move from a first position, spaced from theinlet of the wellbore pump, towards a second position defined by theinlet of the wellbore pump, said treatment formulation being arranged tomove along a fluid path which extends within the wellbore on movingtowards said second position.
 5. The method according to claim 1,wherein said treatment formulation is introduced into the wellbore froman input position, wherein the input position is on an imaginaryvertical line which is spaced horizontally from the inlet of thewellbore by a distance of less than 500 m.
 6. The method according toclaim 1, wherein a filtration device is associated with the wellbore,upstream of the wellbore pump.
 7. The method according to claim 1,wherein said wellbore pump is selected from a progressing cavity pump, abeam pump and a centrifugal pump.
 8. The method according to claim 1,wherein in step (a) the method comprises: selecting a wellbore having ahydrostatic head in the annulus which is less than 300 m above saidlevel; or selecting a wellbore associated with a reservoir which iscapable of yielding more oil if the rate of flow through the wellborecan be increased; or selecting a wellbore having a wellbore pump havinga volumetric efficiency of less than 60%; or selecting a wellborewherein oil in the wellbore has a viscosity in the range 2000 to 50000cp.
 9. The method of claim 8, wherein the oil in the wellbore has aviscosity in the range 2000 to 180,000 cp.
 10. The method according toclaim 1, wherein said treatment formulation includes at least 0.1 wt %of said optionally cross-linked first polymeric material and less than 5wt % of said optionally cross-linked first polymeric.
 11. The methodaccording to claim 1, wherein said treatment formulation includes 0.1 to3 wt % of said optionally cross-linked polymeric material; 0 to 20 wt %of dissolved or dispersed components in addition to said optionallycross-linked polymeric material; 77 to 99.9 wt % water.
 12. The methodaccording to claim 1, wherein said active materials are comprised of atleast 98 wt % of said optionally cross-linked first polymeric material.13. The method according to claim 1, wherein said first polymericmaterial includes a moiety


14. The method according to claim 1, wherein said first polymericmaterial includes a plurality of functional groups selected fromhydroxyl and acetate groups.
 15. The method according to claim 1,wherein said first polymeric material includes a multiplicity ofhydroxyl groups pendant from a polymeric backbone; and also includes amultiplicity of acetate groups pendant from the polymeric backbone. 16.The method according to claim 1, wherein said first polymeric materialincludes a vinyl alcohol monomer unit.
 17. The method according to claim1, wherein said first polymeric material comprises a 5 to 95% hydrolysedpolyvinyl acetate.
 18. The method according to claim 1, wherein saidfirst polymeric material is not cross-linked.
 19. The method accordingto claim 1, wherein use of said treatment formulation increases the rateof flow of fluid passing from the reservoir into the wellbore.
 20. Themethod according to claim 1, wherein said first polymeric material isnot cross-linked and comprises 70 to 95% hydrolysed polyvinylacetate.21. The method according to claim 1, wherein the ratio of the volume ofreservoir fluid to the volume of treatment formulation is in the rangeof 70:30 (reservoir fluid:formulation) to 85:15.
 22. A system associatedwith a wellbore, wherein said wellbore is associated with a reservoirwhich is producing oil and which is capable of yielding more oil if therate of flow through the wellbore can be increased, the systemcomprising: a receptacle above the surface of the ground, the receptaclecontaining a treatment formulation which comprises a first polymericmaterial which includes —O— moieties pendent from a polymeric backbonethereof, wherein the first polymeric material is optionallycross-linked; conduit means extending from the receptacle and beingarranged to deliver treatment formulation from the receptacle to aposition wherein it contacts reservoir fluid, wherein the treatmentformulation is introduced into the formation at a rate of at least 0.1liter/minutes and wherein the wellbore includes a wellbore pump arrangedto pump wellbore fluid within the wellbore to said surface.
 23. A methodof improving the volumetric efficiency of a wellbore pump associatedwith a wellbore, wherein the wellbore pump is arranged to pump wellborefluid within the wellbore to a surface, said method comprising the stepsof: a) selecting a wellbore which includes a wellbore pump having avolumetric efficiency of less than 60%; and b) contacting a reservoirfluid upstream of an inlet of the wellbore pump with a treatmentformulation, wherein said treatment formulation comprises a firstpolymeric material which includes —O— moieties pendent from a polymericbackbone thereof, wherein the first polymeric material is optionallycross-linked; whereby the volumetric efficiency of the wellbore pumpassociated with the reservoir is improved after contact with saidtreatment formulation.
 24. A method of increasing a rate of productionof reservoir fluid from a reservoir which includes a wellbore pumparranged to pump wellbore fluid within the wellbore to a surface, saidmethod comprising the steps of: (a) selecting a wellbore which includesan associated wellbore pump; (b) contacting the reservoir fluid upstreamof an inlet of the wellbore pump with a treatment formulation, whereinsaid treatment formulation comprises a first polymeric material whichincludes —O— moieties pendent from a polymeric backbone thereof, whereinthe first polymeric material is optionally cross-linked; wherein theratio of the volume of reservoir fluid to the volume of treatmentformulation is in the range 70:30 (reservoir fluid:formulation) to85:15; and (c) operating said wellbore pump to recover liquidhydrocarbons from the wellbore at a rate which is greater after contactwith said treatment formulation compared to the rate of recovery ofliquid hydrocarbons before contact with said treatment formulation. 25.A method of increasing a rate of production of reservoir fluid from areservoir which includes a wellbore pump arranged to pump wellbore fluidwithin the wellbore to a surface, said method comprising the steps of:(a) selecting a wellbore which includes an associated wellbore pump; (b)contacting the reservoir fluid upstream of an inlet of the wellbore pumpwith a treatment formulation, wherein said treatment formulationcomprises a first polymeric material which includes —O— moieties pendentfrom a polymeric backbone thereof, wherein the first polymeric materialis optionally cross-linked; wherein the treatment formulation isintroduced into the formation at a rate of at least 0.1 liter/minute;and (c) operating said wellbore pump to recover liquid hydrocarbons fromthe wellbore at the rate which is greater after contact with saidtreatment formulation compared to the rate of recovery of liquidhydrocarbons before contact with said treatment formulation.